1. Field of the Invention
This invention relates generally to methods and apparatus for remotely monitoring, controlling, and automating the operation of pumps for the production of hydrocarbons and dewatering, for example, and more specifically to a controller for rod pumps, progressing cavity pumps, injection well control, variable speed drives, well gas measurement, et cetera, for continuous optimization thereof.
2. Description of the Prior Art
Hydrocarbons are often produced from well bores by sucker rod pumps, reciprocating pumps driven from the surface by pumping units that move a polished rod up and down through a packing gland at a wellhead. The units may be of the predominant beam type or any other type that reciprocates the polished rod.
Because the incremental cost of larger sucker rod pumps is usually less than the added value realized by producing oil from the wells at the highest possible rate, sucker rod pumping units are typically sized to pump faster than the wells can produce. Consequently, sucker rod pumps periodically run out of liquids to pump and draw gas into the cylinders through the standing valves. The term “pumped-off” is used to describe the condition where the fluid level in the well is not sufficient to completely fill the pump barrel on the upstroke. On the next down stroke the plunger will impact the fluid surface in the incompletely filled barrel and send shock waves through the rod string and other components of the pumping system. This “fluid pound” lowers well production efficiency and over time can cause damage to the drive unit or downhole pump, such as broken rods.
To minimize running pumped-off, sucker rod pumps are generally operated with some type of controller. Early controllers consist of simple controllers, such as clock timers that start and stop the pumping unit in response to a user selectable program, allowing the well to fill during the times when the pump is switched off. However, simple clock timers are not responsive to actual well conditions and do not detect actual pump-off conditions.
Thus, in the early 1970s, a viable well control method evolved using more sophisticated controllers that stop the rod pump when a well actually pumps-off. This method is known as pump off control (POC). Over the years, POC has employed different algorithms to sense pump-off conditions. Some of these involve measurement of changes in surface load, motor current, or motor speed.
In addition to running a rod pump in a pumped-off state, other abnormal conditions of the pump operation reduce well production efficiency. Common abnormal conditions include tubing movement, gas interference, an inoperative pump, the pump hitting up or down, a bent barrel, a sticking pump, a worn plunger or traveling valve, a worn standing valve, a worn or split barrel, fluid friction, and drag friction. As many of these problems gradually appear and progressively worsen, early detection of these problems can often minimize the cost of maintenance, minimize the cost of inefficient operation, and prevent or minimize the loss of production.
Traditionally, troubleshooting and repair of pump problems requires lifting the entire down-hole unit to the surface. It is not unusual to have a mile or more of sucker rods or tubing that must be lifted and disassembled by a single or pair of twenty-five or thirty foot long sections at a time. This method of pump diagnosis and troubleshooting is costly both in terms of labor costs and lost revenue from the well.
Fortunately, many pump health indications and abnormal operating conditions can be detected by accurate monitoring of the pump operation, reducing the need for physical inspection of the downhole pump components and lowering the cost of well troubleshooting. Thus, from its humble beginning of merely stopping the well to prevent the mechanical damage of fluid pound and the inefficiency associated with operating an incompletely filled pump, POC has evolved in the last quarter century into a diagnostic system with robust well management capabilities. Gradually the phrase “pump off control” has been replaced with terms like “well manager,” “rod pump controller,” et cetera. (Lufkin Automation uses the trademark SAM® Well manager to identify its rod pump control system.) These newer terms connote more than pump off control. The later systems generally include diagnostic capability and collection and analysis of performance data for operation of the well in an economic fashion.
Many of these intelligent well controllers monitor work performed, or something that relates to work performed, as a function of polished rod position. This information is used, for example, to determine if the well is in a pumped-off condition, if valves are leaking or stuck, or for troubleshooting a wide variety of other problems. This information is generally presented and analyzed in the form of a plot of polished rod load versus polished rod position as measured at the surface. For a normally operating pump, the shape of this plot, known as a “surface card” or “surface dynagraph,” is generally an irregular elliptical shape. The area bounded by this curve, often referred to as the surface card area, is proportional to the work performed by the pump. Many pump-off controllers utilize a surface dynagraph plot to determine when the sucker rod pump is not filling to shutdown the pump for a time period. For example, U.S. Pat. No. 3,951,209, issued Apr. 20, 1976 to Gibbs, describes a controller that measures at the surface both the load on the rod string and the displacement of the rod string to determine a pump-off condition and is incorporated herein by reference.
However, because the surface card is not always an accurate representation of the load and displacement of the downhole rod string, particularly for deep wells, more accurate well control is achieved by using a “downhole card,” i.e., a plot of load versus rod string displacement as measured at the downhole pump. The downhole card is immensely useful. Its shape reveals defective pumps, completely filled pumps, gassy or pounding wells, unanchored tubing, parted rods, etc. Furthermore, the downhole card can be used to sense tubing leaks. Quantitative computation of pump leakage from downhole cards is described in “Quantitative Determination of Rod-Pump Leakage with Dynamometer Techniques,” Nolen, Gibbs, SPE Production Engineering, August 1990.
When first developed in 1936, the downhole pump card was directly measured by a dynamometer located at the subsurface pump. The measured data was retrieved by the costly process of pulling the rods and pump. Because even today these measurements are not easily directly obtained, requiring a costly telemetry system to relay the data to the surface, methods have been developed to calculate the downhole dynagraph from the more easily obtained surface card. One such method is described in U.S. Pat. No. 3,343,409 (Gibbs), which is incorporated herein by reference. Gibbs utilizes surface measurements of load and position of the rod string to construct a downhole pump card; to produce the downhole card, solutions to a wave equation to satisfy dynamometer time histories of surface rod load and position are calculated by the use of a computer.
In addition to identification of abnormal well conditions or pump malfunctions, the most advanced of today's well managers can also infer well production rates with considerable accuracy by using the subsurface pump as a flow meter and the downhole card to compute producing pressure, liquid and gas throughput, and oil shrinkage effects. In other words, production rates can be determined continuously without the use of traditional metering equipment or production tests. For example, a decline in production rate can corroborate a mechanical problem indicated by a downhole card; the downhole pump may be worn or a tubing leak may have developed. The decline may also be caused by a change in reservoir conditions in the drainage area of the well; the receptivity of an offset injection well may have diminished, which may have resulted in a producing pressure decline and a decrease in production rate. Conversely, an increase in productivity as calculated by a well manager may indicate that the well is responding to secondary recovery efforts; the well should be pumped more aggressively to obtain the increased production that is available. These sophisticated well managers are instrumental in many facets of oil production including economic operation of the oilfield as a business venture, compliance with governmental regulations, well troubleshooting, and estimation of reservoir reserves. A method of inferred production using a well manager is taught by Gibbs in co-pending U.S. patent application Ser. No. 10/940,273, which is incorporated herein by reference.
Of significant use is the ability of well managers to communicate with a central host computer for supervisory control and data acquisition (SCADA). For example, a well manager unit receives surface rod and load information (or equivalent measurements), measures a surface card, computes a downhole card, and locally displays a graphical representation of the surface card and/or the downhole card for the operators' ease and benefit. However, the benefit of the well manager features is diminished when the operator must be present at the well site to see and analyze the well data. A well manager with SCADA capability, on the other hand, can automatically transfer well data to a distantly located control station. SCADA allows information about the subsurface pump, including well and pump performance data, inferred fluid production over time, and surface and downhole cards, to be both displayed locally for manual recording and automatically sent to a distant central location. Furthermore, the SCADA system may be configured to send alarms, allowing problems to be timely announced. Control signals may also be sent from the central control station to the well manager. SCADA capability reduces or eliminates the need for an individual to visit the well site to determine the status at the controller and results in several advantages, including reducing delays in notifying the operator of alert or alarm conditions, increasing the accuracy of the disseminated well manager data, lowering costs of managing oil fields, and minimizing the need for the operator to visit potentially hazardous well sites. Thus, most sophisticated well managers have a built-in SCADA capability to communicate data by radio, hardwire, or telephone. This telemetry capability makes it possible for one or more computers to retrieve data from a controller, obtain status of operations, issue control instructions, monitor for alarms, and develop reports.
Although current SCADA systems provide some remote connectivity between a remote site and a number of well managers in an oil field, they generally employ expensive proprietary hardware and short-range RF radios of low bandwidth. Typical SCADA systems are polling systems that can only interrogate each well a few times each day to retrieve dynamometer and other performance data. Therefore downhole pump cards can on average be reviewed at the central location via SCADA only a few times each day.
Therefore, it is desirable to provide higher data throughput and continuous connectivity to a well manager by exploiting current internet technology. Such technology integrated with today's sophisticated well controllers would allow more well data to be collected at a central location at a lower cost. Several patents address connecting an oilfield to the internet. For example, U.S. Pat. No. 6,857,474 issued to Bramlett et al. on Feb. 22, 2005 shows a rod pump well manager with the capability to display a graphical pump card at a remote output display via an internet link 131 and is incorporated herein by reference. However, Bramlett's teaching is limited to using the internet to remotely display graphical surface and downhole cards; Bramlett does not disclose sending well production reports, statistics, pump diagnostics, alarms, alerts or other data from the well manager to remote users via the internet or receiving control data at the well manager from remote users over the internet.
The method according to U.S. Pat. No. 7,096,092 issued to Ramakrishnan et al. on Aug. 22, 2006 is illustrated in FIG. 1. Ramakrishnan shows a method of managing oil fields including installing oil field sensors (50) on oil wells (60, 61, 62), connecting the sensors (50) to computer controllers (52) disposed at the wells (60, 61, 62) for data collection and data analysis, and connecting a number of local oil field controllers (52) to a central web server (54). Access to oil field data in real time is provided to a remote computer (56) via the internet (1000). Raw data, partially analyzed data, or fully analyzed data is available remotely. The local controllers (52) are programmed with parameters for analyzing the data and automatically determining the presence of anomalies. Upon detecting the occurrence of an anomaly, the local controllers (52) are programmed to notify, via the central web server (54), an operator by email, pager, telephone, et cetera. If no response to the notification is received within a programmed period of time, the local controllers (52) automatically take pre-programmed corrective action. Ramakrishnan does not disclose that the controllers are adapted to control rod pumps or that the controllers calculate downhole and surface cards or infer production.
U.S. Pat. No. 6,967,589 issued to Peters on Nov. 22, 2005 and illustrated in FIG. 2 shows a system for monitoring gas/oil wells with a local monitoring unit (58) located at each well (61, 62), a central field-located relay unit (64) in wireless short range RF communication with a number of monitoring units (58), and a host interface linked (66) with the relay unit (64) via the internet (1000). The monitoring units (58) collect data regarding the status of the gas/oil wells (61, 62) and wirelessly transmit that data to the relay unit (64). The relay unit (64), in turn, connects to a host interface (66) over the internet (1000) and transmits the data. That is, a central field-wide web-enabled relay unit (64) is used for numerous well monitoring units (58). Each monitoring unit (58) can transmit information on demand or after an alarm condition is sensed. The relay unit (64) can request information from a monitoring unit (58) or respond to a wake up transmission sent to it from either the host interface (66) or a monitoring unit (58). The host interface (66) receives data from the relay unit (58) for providing data to an operator. Peters does not disclose that the well monitors (58) are adapted to control rod pumps or that they calculate downhole and surface cards or infer production.
Also illustrated by FIG. 2, U.S. Pat. No. 6,898,149 issued to Hill et al. on May 24, 2005 shows a data communications system for use with an oil or gas well (60) including downhole well sensors (67) that communicate via a conventional wireless SCADA interface (68) to a local internet server (64) located in the oil field. In other words, a field-wide web server (64) is used for servicing numerous wells. The internet server (64) acts to transmit data logging at remote points for display. Hill does not disclose controllers adapted to control rod pumps or to calculate downhole and surface cards.
Referring to FIG. 3, U.S. Pat. No. 6,873,267 issued to Tubel et al. on Mar. 29, 2005 shows a system for monitoring and controlling hydrocarbon production wells (63, 65) from a first remote location (70) including a surface control and data acquisition systems (72, 74) each with one or more sensors or downhole flow control devices (76, 78). The surface control and data acquisition systems (72, 74) are in satellite communication with a remote controller (80) disposed at a second remote location (82). The remote controller includes an internet web site server for providing access to end users at the first remote location (70) over the internet (1000). The internet server (80) is disposed at a remote location, not locally at each well (63, 65) or at the surface control and data acquisition systems (72, 74). Tubel does not disclose that the system is adapted to control rod pumps or to calculate downhole and surface cards.
Finally, U.S. Pat. No. 6,498,988 issued to Robert et al. on Dec. 24, 2002 shows a technique for centralized processing for design and analysis on a server computer of oilfield engineering data transmitted over the internet from client computers at distributed locations. The data is processed at the remote server computing device and the results are communicated over the internet to the client computing device. Although each remote client computer has internet connectivity, they do not function as internet servers, and the data is not processed locally.